XNYS:ETP Energy Transfer Partners LP Quarterly Report 10-Q Filing - 3/31/2012

Effective Date 3/31/2012

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
__________________________________ 
FORM 10-Q
__________________________________ 
ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2012
or
 
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-11727
__________________________________ 
ENERGY TRANSFER PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
__________________________________ 
Delaware
 
73-1493906
(state or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
3738 Oak Lawn Avenue, Dallas, Texas 75219
(Address of principal executive offices) (zip code)
(214) 981-0700
(Registrant’s telephone number, including area code)
__________________________________ 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ý    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ý    No  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
 
ý
  
Accelerated filer
 
¨
 
 
 
 
Non-accelerated filer
 
¨  (Do not check if a smaller reporting company)
  
Smaller reporting company
 
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  ý
At May 2, 2012, the registrant had units outstanding as follows:
Energy Transfer Partners, L.P.                229,563,121        Common Units
 



FORM 10-Q
TABLE OF CONTENTS
Energy Transfer Partners, L.P. and Subsidiaries
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 



i


Forward-Looking Statements
Certain matters discussed in this report, excluding historical information, as well as some statements by Energy Transfer Partners, L.P. (“Energy Transfer Partners,” the “Partnership,” or "ETP") in periodic press releases and some oral statements of the Partnership’s officials during presentations about the Partnership, include forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect,” “continue,” “estimate,” “goal,” “forecast,” “may,” “will” or similar expressions help identify forward-looking statements. Although the Partnership and its General Partner believe such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that such assumptions, expectations, or projections will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, the Partnership’s actual results may vary materially from those anticipated, projected or expected, forecasted, estimated or expressed in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks that are difficult to predict and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see “Part II — Other Information – Item 1A. Risk Factors” in this Quarterly Report on Form 10-Q, as well as “Part I — Item 1A. Risk Factors” in the Partnership’s Report on Form 10-K for the year ended December 31, 2011 filed with the Securities and Exchange Commission on February 22, 2012.
Definitions
The following is a list of certain acronyms and terms generally used throughout this document:
 
/d
  
per day
 
 
 
 
AmeriGas
 
AmeriGas Partners, L.P.
 
 
 
 
 
AOCI
 
accumulated other comprehensive income
 
 
 
 
 
Bbls
  
barrels
 
 
 
 
Bcf
  
billion cubic feet
 
 
 
 
 
Btu
  
British thermal unit, an energy measurement used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy used
 
 
 
 
CAA
 
Clean Air Act
 
 
 
 
 
Capacity
  
capacity of a pipeline, processing plant or storage facility refers to the maximum capacity under normal operating conditions and, with respect to pipeline transportation capacity, is subject to multiple factors (including natural gas injections and withdrawals at various delivery points along the pipeline and the utilization of compression) which may reduce the throughput capacity from specified capacity levels
 
 
 
 
 
Credit Suisse
 
Credit Suisse Securities (USA) LLC
 
 
 
 
DOT
 
U.S. Department of Transportation
 
 
 
 
 
El Paso
 
El Paso Corporation
 
 
 
 
 
ETC Compression
 
ETC Compression, LLC
 
 
 
 
 
ETC FEP
 
ETC Fayetteville Express Pipeline, LLC
 
 
 
 
 
ETC OLP
 
La Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company
 
 
 
 
 
ETC Tiger
 
ETC Tiger Pipeline, LLC
 
 
 
 
 
ETE
 
Energy Transfer Equity, L.P., a publicly traded partnership and the owner of ETP LLC
 
 
 
 
 
ET Interstate
 
Energy Transfer Interstate Holdings, LLC
 
 
 
 
 
ETP GP
 
Energy Transfer Partners GP, L.P., the general partner of ETP
 
 
 
 
ETP LLC
 
Energy Transfer Partners, L.L.C., the general partner of ETP GP
 
 
 
 
EPA
 
U.S. Environmental Protection Agency
 
 
 
 

ii


 
Exchange Act
 
Securities Exchange Act of 1934
 
 
 
 
 
FEP
 
Fayetteville Express Pipeline LLC
 
 
 
 
 
FERC
 
Federal Energy Regulatory Commission
 
 
 
 
 
FGT
 
Florida Gas Transmission Company, LLC
 
 
 
 
 
GAAP
  
accounting principles generally accepted in the United States of America
 
 
 
 
HOLP
 
Heritage Operating, L.P.
 
 
 
 
 
ICA
 
Interstate Commerce Act
 
 
 
 
 
IDRs
 
incentive distribution rights
 
 
 
 
 
LDH
 
LDH Energy Asset Holdings LLC
 
 
 
 
 
LIBOR
  
London Interbank Offered Rate
 
 
 
 
Lone Star
 
Lone Star NGL LLC
 
 
 
 
 
MMBtu
  
million British thermal units
 
 
 
 
 
NGA
 
Natural Gas Act
 
 
 
 
 
NGL
  
natural gas liquid, such as propane, butane and natural gasoline
 
 
 
 
 
NOAA
 
National Oceanic and Atmospheric Administration
 
 
 
 
 
NYMEX
  
New York Mercantile Exchange
 
 
 
 
OTC
 
over-the-counter
 
 
 
 
 
OSHA
 
federal Occupational Safety and Health Act
 
 
 
 
 
PCBs
 
polychlorinated biphenyls
 
 
 
 
 
PHMSA
 
Pipeline Hazardous Materials Safety Administration
 
 
 
 
 
Regency
 
Regency Energy Partners LP
 
 
 
 
 
Reservoir
  
a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs
 
 
 
 
 
SEC
 
Securities and Exchange Commission
 
 
 
 
 
Southern Union
 
Southern Union Company
 
 
 
 
 
Tcf
  
trillion cubic feet
 
 
 
 
 
Titan
 
Titan Energy Partners, L.P.
 
 
 
 
 
Transwestern
 
Transwestern Pipeline Company, LLC
 
Adjusted EBITDA is a term used throughout this document, which we define as earnings before interest, taxes, depreciation, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, loss on extinguishment of debt, gain on deconsolidation of our Propane Business and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities includes unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Adjusted EBITDA reflects amounts for less than wholly owned subsidiaries and unconsolidated affiliates based on the Partnership's proportionate ownership.


iii


PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
(unaudited)
 
 
March 31,
2012
 
December 31,
2011
ASSETS
 
 
 
CURRENT ASSETS:
 
 
 
Cash and cash equivalents
$
156,535

 
$
106,816

Marketable securities
11

 
1,229

Accounts receivable, net of allowance for doubtful accounts of $538 and $7,651 as of March 31, 2012 and December 31, 2011, respectively
476,662

 
568,579

Accounts receivable from related companies
46,330

 
81,753

Inventories
193,906

 
306,740

Exchanges receivable
11,587

 
18,808

Price risk management assets
25,880

 
11,429

Other current assets
145,072

 
180,140

Total current assets
1,055,983

 
1,275,494

PROPERTY, PLANT AND EQUIPMENT
13,339,883

 
13,983,888

ACCUMULATED DEPRECIATION
(1,321,339
)
 
(1,677,522
)
 
12,018,544

 
12,306,366

ADVANCES TO AND INVESTMENTS IN AFFILIATES
3,350,358

 
200,612

LONG-TERM PRICE RISK MANAGEMENT ASSETS
22,470

 
25,537

GOODWILL
614,012

 
1,219,597

INTANGIBLE ASSETS, net
180,160

 
331,409

OTHER NON-CURRENT ASSETS, net
166,263

 
159,601

Total assets
$
17,407,790

 
$
15,518,616








The accompanying notes are an integral part of these consolidated financial statements.

1



ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
(unaudited)
 
 
March 31,
2012
 
December 31,
2011
LIABILITIES AND EQUITY
 
 
 
CURRENT LIABILITIES:
 
 
 
Accounts payable
$
318,823

 
$
401,053

Accounts payable to related companies
4,298

 
33,373

Exchanges payable
9,040

 
17,906

Price risk management liabilities
12,375

 
79,518

Accrued and other current liabilities
504,613

 
629,202

Current maturities of long-term debt
108,224

 
424,117

Total current liabilities
957,373

 
1,585,169

LONG-TERM DEBT, less current maturities
8,741,496

 
7,388,170

LONG-TERM PRICE RISK MANAGEMENT LIABILITIES
88,209

 
42,303

OTHER NON-CURRENT LIABILITIES
172,979

 
152,550

 
 
 
 
COMMITMENTS AND CONTINGENCIES (Note 13)

 

 
 
 
 
EQUITY:
 
 
 
General Partner
181,649

 
181,646

Limited Partners:
 
 
 
Common Unitholders
6,529,759

 
5,533,492

Accumulated other comprehensive income
23,361

 
6,569

Total partners’ capital
6,734,769

 
5,721,707

Noncontrolling interest
712,964

 
628,717

Total equity
7,447,733

 
6,350,424

Total liabilities and equity
$
17,407,790

 
$
15,518,616
















The accompanying notes are an integral part of these consolidated financial statements.

2


ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in thousands, except per unit data)
(unaudited)
 
 
Three Months Ended March 31,
 
2012
 
2011
REVENUES:
 
 
 
Natural gas sales
$
421,416

 
$
599,468

NGL sales
361,577

 
156,901

Gathering, transportation and other fees
388,744

 
336,098

Retail propane sales
75,445

 
528,466

Other
58,678

 
66,644

Total revenues
1,305,860

 
1,687,577

COSTS AND EXPENSES:
 
 
 
Cost of products sold
773,485

 
994,457

Operating expenses
127,990

 
188,489

Depreciation and amortization
101,917

 
95,964

Selling, general and administrative
48,523

 
45,532

Total costs and expenses
1,051,915

 
1,324,442

OPERATING INCOME
253,945

 
363,135

OTHER INCOME (EXPENSE):
 
 
 
Interest expense, net of interest capitalized
(136,820
)
 
(107,240
)
Equity in earnings of affiliates
54,625

 
1,633

Gain on deconsolidation of Propane Business
1,055,944

 

Losses on disposal of assets
(1,024
)
 
(1,726
)
Loss on extinguishment of debt
(115,023
)
 

Gains on non-hedged interest rate derivatives
27,895

 
1,779

Other, net
678

 
218

INCOME BEFORE INCOME TAX EXPENSE
1,140,220

 
257,799

Income tax expense
14,123

 
10,597

NET INCOME
1,126,097

 
247,202

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST
11,364

 

NET INCOME ATTRIBUTABLE TO PARTNERS
1,114,733

 
247,202

GENERAL PARTNER’S INTEREST IN NET INCOME
116,537

 
107,539

LIMITED PARTNERS’ INTEREST IN NET INCOME
$
998,196

 
$
139,663

BASIC NET INCOME PER LIMITED PARTNER UNIT
$
4.36

 
$
0.71

BASIC AVERAGE NUMBER OF UNITS OUTSTANDING
226,549,263

 
193,821,128

DILUTED NET INCOME PER LIMITED PARTNER UNIT
$
4.35

 
$
0.71

DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING
227,406,484

 
194,526,600



The accompanying notes are an integral part of these consolidated financial statements.

3


ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in thousands)
(unaudited)
 
 
Three Months Ended March 31,
 
2012
 
2011
Net income
$
1,126,097

 
$
247,202

Other comprehensive income (loss), net of tax:
 
 
 
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges
(3,482
)
 
(16,968
)
Change in value of derivative instruments accounted for as cash flow hedges
20,388

 
6,159

Change in value of available-for-sale securities
(114
)
 
608

 
16,792

 
(10,201
)
Comprehensive income
1,142,889

 
237,001

Less: Comprehensive income attributable to noncontrolling interest
11,364

 

Comprehensive income attributable to partners
$
1,131,525

 
$
237,001















The accompanying notes are an integral part of these consolidated financial statements.

4


ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF EQUITY
FOR THE THREE MONTHS ENDED MARCH 31, 2012
(Dollars in thousands)
(unaudited)
 
 
General
Partner
 
Limited
Partner
Common
Unitholders
 
Accumulated
Other
Comprehensive
Income
 
Noncontrolling
Interest
 
Total
Balance, December 31, 2011
$
181,646

 
$
5,533,492

 
$
6,569

 
$
628,717

 
$
6,350,424

Distributions to partners
(116,540
)
 
(202,057
)
 

 

 
(318,597
)
Distributions to noncontrolling interest

 

 

 
(6,956
)
 
(6,956
)
Units issued for cash

 
87,327

 

 

 
87,327

Capital contributions from noncontrolling interest

 

 

 
79,839

 
79,839

Units issued in connection with Citrus Merger

 
105,000

 

 

 
105,000

Distributions on unvested unit awards

 
(2,023
)
 

 

 
(2,023
)
Non-cash compensation expense, net of units tendered by employees for tax withholdings
6

 
10,799

 

 

 
10,805

Other comprehensive income, net of tax

 

 
16,792

 

 
16,792

Other, net


 
(975
)
 

 

 
(975
)
Net income
116,537

 
998,196

 

 
11,364

 
1,126,097

Balance, March 31, 2012
$
181,649

 
$
6,529,759

 
$
23,361

 
$
712,964

 
$
7,447,733













The accompanying notes are an integral part of these consolidated financial statements.

5


ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in thousands)
(unaudited)
 
 
Three Months Ended March 31,
 
2012
 
2011
CASH FLOWS PROVIDED BY OPERATING ACTIVITIES:
 
 
 
Net income
$
1,126,097

 
$
247,202

Reconciliation of net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization
101,917

 
95,964

Amortization of finance costs charged to interest
2,984

 
2,298

Loss on extinguishment of debt
115,023

 

Non-cash compensation expense
10,709

 
10,189

Gain on deconsolidation of Propane Business
(1,055,944
)
 

Losses on disposal of assets
1,024

 
1,726

Distributions on unvested awards
(2,023
)
 
(1,788
)
Distributions in excess of (less than) equity in earnings of affiliates, net
(18,064
)
 
4,687

Other non-cash
7,682

 
2,142

Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidation (see Note 3)
(34,406
)
 
(71,833
)
Net cash provided by operating activities
254,999

 
290,587

CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
Cash paid for Citrus Merger
(1,895,000
)
 

Cash proceeds from contribution of Propane Business
1,383,802

 

Cash paid for all other acquisitions, net of cash received
(10,066
)
 
(3,060
)
Capital expenditures (excluding allowance for equity funds used during construction)
(519,042
)
 
(210,955
)
Contributions in aid of construction costs
5,732

 
2,754

Distributions from (advances to) affiliates, net
3,890

 
(11,053
)
Proceeds from the sale of assets
12,845

 
681

Net cash used in investing activities
(1,017,839
)
 
(221,633
)
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
Proceeds from borrowings
2,558,084

 
917,094

Repayments of long term debt
(1,556,287
)
 
(758,615
)
Net proceeds from issuance of Limited Partner units
87,327

 
57,373

Capital contributions from noncontrolling interest
67,128

 

Distributions to partners
(318,597
)
 
(274,208
)
Distributions to noncontrolling interest
(6,956
)
 

Debt issuance costs
(18,140
)
 

Net cash provided by (used in) financing activities
812,559

 
(58,356
)
INCREASE IN CASH AND CASH EQUIVALENTS
49,719

 
10,598

CASH AND CASH EQUIVALENTS, beginning of period
106,816

 
49,540

CASH AND CASH EQUIVALENTS, end of period
$
156,535

 
$
60,138


The accompanying notes are an integral part of these consolidated financial statements.

6


ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Tabular dollar amounts, except per unit data, are in thousands)
(unaudited)
 
1.
OPERATIONS AND ORGANIZATION:
Energy Transfer Partners, L.P. and its subsidiaries (“Energy Transfer Partners,” the “Partnership,” “we” or “ETP”) are managed by ETP’s general partner, ETP GP, which is in turn managed by its general partner, ETP LLC. ETE, a publicly traded master limited partnership, owns ETP LLC, the general partner of our General Partner. The consolidated financial statements of the Partnership presented herein include our operating subsidiaries described below.
Business Operations
Our activities are primarily conducted through our operating subsidiaries (collectively, the “Operating Companies”) as follows:
ETC OLP, a Texas limited partnership engaged in midstream and intrastate transportation and storage natural gas operations. ETC OLP owns and operates, through its wholly and majority-owned subsidiaries, natural gas gathering systems, intrastate natural gas pipeline systems and gas processing plants and is engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico, Utah, West Virginia and Colorado. Our intrastate transportation and storage operations primarily focus on transporting natural gas in Texas through our Oasis pipeline, ET Fuel System, East Texas pipeline and HPL System. Our midstream operations focus on the gathering, compression, treating, conditioning and processing of natural gas, primarily on or through our Southeast Texas System, North Texas System and Northern Louisiana assets. We also own and operate natural gas gathering pipelines and conditioning facilities in the Piceance and Uinta Basins of Colorado and Utah, respectively. ETC OLP also owns a 70% interest in Lone Star.
ET Interstate, a Delaware limited liability company with revenues consisting primarily of fees earned from natural gas transportation services and operational gas sales. ET Interstate is the parent company of:
Transwestern, a Delaware limited liability company engaged in interstate transportation of natural gas. Transwestern’s revenues consist primarily of fees earned from natural gas transportation services and operational gas sales.
ETC FEP, a Delaware limited liability company engaged in interstate transportation of natural gas.
ETC Tiger, a Delaware limited liability company engaged in interstate transportation of natural gas.
CrossCountry Energy, LLC, a Delaware limited liability company that indirectly owns a 50% interest in Citrus Corp.
ETC Compression, a Delaware limited liability company engaged in natural gas compression services and related equipment sales.
On January 12, 2012, we contributed HOLP and Titan to AmeriGas. See Note 5.
Our historical financial statements reflect the following reportable business segments: intrastate natural gas transportation and storage; interstate natural gas transportation; midstream; NGL transportation and services; and retail propane and other retail propane related operations.
Preparation of Interim Financial Statements
The accompanying consolidated balance sheet as of December 31, 2011, which has been derived from audited financial statements, and the unaudited interim consolidated financial statements and notes thereto of Energy Transfer Partners as of March 31, 2012 and for the three months ended March 31, 2012 and 2011, have been prepared in accordance with GAAP for interim consolidated financial information and pursuant to the rules and regulations of the SEC. Accordingly, they do not include all the information and footnotes required by GAAP for complete consolidated financial statements. However, management believes that the disclosures made are adequate to make the information not misleading. The results of operations for interim periods are not necessarily indicative of the results to be expected for a full year due to the seasonal nature of the Partnership’s operations, maintenance activities and the impact of forward natural gas prices and differentials on certain derivative financial instruments that are accounted for using mark-to-market accounting. Management has evaluated subsequent events through the date the financial statements were issued.
In the opinion of management, all adjustments (all of which are normal and recurring) have been made that are necessary to fairly state the consolidated financial position of Energy Transfer Partners as of March 31, 2012, and the Partnership’s results

7


of operations and cash flows for the three months ended March 31, 2012 and 2011. The unaudited interim consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto of Energy Transfer Partners presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2011, as filed with the SEC on February 22, 2012.
Certain prior period amounts have been reclassified to conform to the 2012 presentation. These reclassifications had no impact on net income or total equity.
Pending Sunoco Merger
On April 30, 2012, we announced our entry into a definitive merger agreement whereby we will acquire Sunoco Inc.in a common unit and cash transaction valued at $5.3 billion based on our unit closing price on April 27, 2012. Under the terms of the merger agreement, Sunoco shareholders would receive, for each Sunoco common share, either $50.00 in cash, 1.0490 ETP Common Units or a combination of $25.00 in cash and 0.5245 ETP Common Units. The aggregate cash paid and ETP Common Units issued will be capped so that the cash and ETP Common Units will each represent 50% of the aggregate consideration. Upon closing, Sunoco shareholders are expected to own approximately 20% of our outstanding limited partner interests. This transaction is expected to close in the third or fourth quarter of 2012, subject to approval by Sunoco's shareholders and customary regulatory approvals.
In connection with the transaction, ETE has agreed to relinquish their right to approximately $210 million of IDRs from us that ETE would otherwise receive over 12 consecutive quarters following the closing of the transaction.
Sunoco owns the general partner interest of Sunoco Logistics, consisting of a 2% ownership interest and IDRs, and 32.4% of the outstanding common units of Sunoco Logistics. Sunoco also generates cash flow from a portfolio of 4,900 retail outlets for the sale of gasoline and middle distillates in the east coast, midwest and southeast areas of the United States.
Sunoco Logistics is a publicly traded limited partnership that owns and operates a logistics business consisting of a geographically diverse portfolio of complementary pipeline, terminalling and crude oil acquisition and marketing assets. The refined products pipelines business consists of approximately 2,500 miles of refined products pipelines located in the northeast, midwest and southwest United States, and equity interests in four refined products pipelines. The crude oil pipeline business consists of approximately 5,400 miles of crude oil pipelines, located principally in Oklahoma and Texas. The terminal facilities business consists of approximately 42 million shell barrels of refined products and crude oil terminal capacity (including approximately 22 million shell barrels of capacity at the Nederland Terminal on the Gulf Coast of Texas and approximately 5 million shell barrels of capacity at the Eagle Point terminal on the banks of the Delaware River in New Jersey). The crude oil acquisition and marketing business involves the acquisition and marketing of crude oil and is principally conducted in Oklahoma and Texas and consists of approximately 190 crude oil transport trucks and approximately 120 crude oil truck unloading facilities.

2.
ESTIMATES:
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.
The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for our natural gas and NGL related operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects.
Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.

3.
CASH AND CASH EQUIVALENTS:
Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value.

8


We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.
The net change in operating assets and liabilities (net of effects of acquisitions and deconsolidation) included in cash flows from operating activities is comprised as follows:
 
Three Months Ended March 31,
 
2012
 
2011
Accounts receivable
$
(35,024
)
 
$
10,469

Accounts receivable from related companies
(57,282
)
 
(24,685
)
Inventories
23,050

 
65,950

Exchanges receivable
7,222

 
5,330

Other current assets
54,503

 
(34,575
)
Other non-current assets, net
2,447

 
2,353

Accounts payable
(15,352
)
 
(35,787
)
Accounts payable to related companies
75,619

 
(6,094
)
Exchanges payable
(8,865
)
 
4,846

Accrued and other current liabilities
(65,749
)
 
(55,534
)
Other non-current liabilities
(5,911
)
 
2,335

Price risk management assets and liabilities, net
(9,064
)
 
(6,441
)
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidation
$
(34,406
)
 
$
(71,833
)
Non-cash investing and financing activities are as follows:
 
Three Months Ended March 31,
 
2012
 
2011
NON-CASH INVESTING ACTIVITIES:

 

Accrued capital expenditures
$
201,845

 
$
90,846

AmeriGas limited partner interests received in exchange for contribution of Propane Business (See Note 5)
$
1,123,003

 
$

NON-CASH FINANCING ACTIVITIES:
 
 
 
Issuance of common units in connection with Citrus Merger
$
105,000

 
$


4.
INVENTORIES:
Inventories consisted of the following: 
 
March 31,
2012
 
December 31, 2011
Natural gas and NGLs, excluding propane
$
125,054

 
$
144,251

Propane
2,895

 
86,958

Appliances, parts and fittings and other
65,957

 
75,531

Total inventories
$
193,906

 
$
306,740

We utilize commodity derivatives to manage price volatility associated with our natural gas inventory and designate certain of these derivatives as fair value hedges for accounting purposes. Changes in fair value of the designated hedged inventory have been recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations.



9


5.
INVESTMENTS IN AFFILIATES:
Citrus Merger
On March 26, 2012, ETE consummated the acquisition of Southern Union and, concurrently with the closing of the Southern Union Acquisition, CrossCountry Energy, LLC (“CrossCountry”), a subsidiary of Southern Union that indirectly owns a 50% interest in Citrus Corp. (“Citrus”), merged with a subsidiary of ETP and, in connection therewith, ETP paid $1.9 billion in cash and issued $105 million of ETP Common Units (the “Citrus Merger”). As a result of the consummation of the Citrus Merger, ETP owns CrossCountry which in turn owns a 50% interest in Citrus. The other 50% interest in Citrus is owned by El Paso.
Citrus owns 100% of FGT, a natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula.
We recorded our investment in Citrus at $2.0 billion, which exceeded our proportionate share of Citrus' equity by $1.03 billion, all of which is treated as equity method goodwill due to the application of regulatory accounting.
Propane Operations
On January 12, 2012, we contributed our propane operations, consisting of HOLP and Titan (collectively, the “Propane Business”) to AmeriGas. We received approximately $1.46 billion in cash and approximately 29.6 million AmeriGas Common Units valued at $1.12 billion at the time of the contribution. AmeriGas assumed approximately $71.0 million of existing HOLP debt. We recognized a gain on deconsolidation of $1.06 billion and recorded $39.4 million of equity in earnings related to AmeriGas for the three months ended March 31, 2012. The cash proceeds were used to complete our tender offer of existing debt (see Note 9) in January 2012 and to repay borrowings on our revolving credit facility.
Our investment in AmeriGas reflected $639.6 million in excess of our proportionate share of AmeriGas' limited partners' capital. Of this excess fair value, $177.3 million is being amortized over a weighted average period of 12 years, and $462.3 million is being treated as equity method goodwill and non-amortizable intangible assets.
In connection with the closing of this transaction, we entered into a support agreement with AmeriGas (See Note 13). Under a unitholder agreement with AmeriGas, we are also obligated to hold the approximately 29.6 million AmeriGas Common Units that we received in this transaction until January 2013.
We have not reflected our Propane Business as discontinued operations as we will have a continuing involvement in this business as a result of our investment in AmeriGas.

6.
GOODWILL AND INTANGIBLE ASSETS:
A net decrease in goodwill of $605.6 million was recorded during the three months ended March 31, 2012 due to the contribution of HOLP and Titan to AmeriGas. See Note 5.
Components and useful lives of intangible assets were as follows:
 
March 31, 2012
 
December 31, 2011
 
Gross Carrying
Amount
 
Accumulated
Amortization
 
Gross Carrying
Amount
 
Accumulated
Amortization
Amortizable intangible assets:
 
 
 
 
 
 
 
Customer relationships, contracts and agreements (3 to 46 years)
$
231,308

 
$
(54,413
)
 
$
338,424

 
$
(95,239
)
Noncompete agreements (3 to 15 years)
742

 
(297
)
 
15,431

 
(7,835
)
Patents (9 years)
750

 
(222
)
 
750

 
(201
)
Other (10 to 15 years)
843

 
(117
)
 
1,320

 
(580
)
Total amortizable intangible assets
233,643

 
(55,049
)
 
355,925

 
(103,855
)
Non-amortizable intangible assets:
 
 
 
 
 
 
 
Trademarks
1,566

 

 
79,339

 

Total intangible assets
$
235,209

 
$
(55,049
)
 
$
435,264

 
$
(103,855
)

10


Aggregate amortization expense of intangible assets was as follows:
 
Three Months Ended March 31,
 
2012
 
2011
Reported in depreciation and amortization
$
4,408

 
$
5,051

Estimated aggregate amortization expense for the next five years is as follows:
2012 (remainder)
$
11,590

2013
11,694

2014
10,569

2015
10,569

2016
10,569


7.
FAIR VALUE MEASUREMENTS:
The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. Price risk management assets and liabilities are recorded at fair value.
We have marketable securities, commodity derivatives and interest rate derivatives that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 since we use a LIBOR curve based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements and discount the future cash flows accordingly, including the effects of credit risk. Level 3 inputs are unobservable. We currently do not have any recurring fair value measurements that are considered Level 3 valuations. During the period ended March 31, 2012, no transfers were made between any levels within the fair value hierarchy.
Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our consolidated debt obligations at March 31, 2012 was $9.72 billion and $8.85 billion, respectively. As of December 31, 2011, the aggregate fair value and carrying amount of our consolidated debt obligations was $8.39 billion and $7.81 billion, respectively. We consider the fair value of our consolidated debt obligations as a Level 2 valuation based on the observable inputs used for similar liabilities.

11


The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of March 31, 2012 and December 31, 2011 based on inputs used to derive their fair values:
 
 
Fair Value Measurements  at
March 31, 2012
 
Fair Value
Total
 
Level 1
 
Level 2
Assets:
 
 
 
 
 
Marketable securities
$
11

 
$
11

 
$

Interest rate derivatives
33,998

 

 
33,998

Commodity derivatives:
 
 
 
 
 
Natural Gas:
 
 
 
 
 
Basis Swaps IFERC/NYMEX
47,657

 
47,657

 

Swing Swaps IFERC
19,093

 
2,856

 
16,237

Fixed Swaps/Futures
170,565

 
170,565

 

Options — Puts
6,765

 

 
6,765

Forward Physical Swaps
3,367

 

 
3,367

Power:


 
 
 
 
Forwards
11,562

 
364

 
11,198

Options — Puts
85

 
85

 

Options — Calls
107

 
107

 

Total commodity derivatives
259,201

 
221,634

 
37,567

Total Assets
$
293,210

 
$
221,645

 
$
71,565

Liabilities:
 
 
 
 
 
Interest rate derivatives
$
(88,092
)
 
$

 
$
(88,092
)
Commodity derivatives:
 
 
 
 
 
Natural Gas:
 
 
 
 
 
Basis Swaps IFERC/NYMEX
(73,305
)
 
(73,305
)
 

Swing Swaps IFERC
(20,646
)
 
(5,024
)
 
(15,622
)
Fixed Swaps/Futures
(116,877
)
 
(116,877
)
 

Options — Calls
(2
)
 

 
(2
)
Forward Physical Swaps
(918
)
 

 
(918
)
Propane — Forwards/Swaps
(879
)
 

 
(879
)
Power:
 
 
 
 
 
Forwards
(11,152
)
 
(383
)
 
(10,769
)
Options — Calls
(40
)
 
(40
)
 

Total commodity derivatives
(223,819
)
 
(195,629
)
 
(28,190
)
Total Liabilities
$
(311,911
)
 
$
(195,629
)
 
$
(116,282
)


12


 
 
Fair Value Measurements  at
December 31, 2011
 
Fair Value
Total
 
Level 1
 
Level 2
Assets:
 
 
 
 
 
Marketable securities
$
1,229

 
$
1,229

 
$

Interest rate derivatives
36,301

 

 
36,301

Commodity derivatives:
 
 
 
 
 
Natural Gas:
 
 
 
 
 
Basis Swaps IFERC/NYMEX
62,924

 
62,924

 

Swing Swaps IFERC
15,002

 
1,687

 
13,315

Fixed Swaps/Futures
214,572

 
214,572

 

Options — Puts
6,435

 

 
6,435

Forward Physical Swaps
699

 

 
699

Propane – Forwards/Swaps
9

 

 
9

Total commodity derivatives
299,641

 
279,183

 
20,458

Total Assets
$
337,171

 
$
280,412

 
$
56,759

Liabilities:
 
 
 
 
 
Interest rate derivatives
$
(117,020
)
 
$

 
$
(117,020
)
Commodity derivatives:
 
 
 
 
 
Natural Gas:
 
 
 
 
 
Basis Swaps IFERC/NYMEX
(82,290
)
 
(82,290
)
 

Swing Swaps IFERC
(16,074
)
 
(3,061
)
 
(13,013
)
Fixed Swaps/Futures
(148,111
)
 
(148,111
)
 

Options — Calls
(12
)
 

 
(12
)
Forward Physical Swaps
(712
)
 

 
(712
)
Propane – Forwards/Swaps
(4,131
)
 

 
(4,131
)
Total commodity derivatives
(251,330
)
 
(233,462
)
 
(17,868
)
Total Liabilities
$
(368,350
)
 
$
(233,462
)
 
$
(134,888
)

8.
NET INCOME PER LIMITED PARTNER UNIT:
Our net income for partners’ capital and statement of operations presentation purposes is allocated to ETP GP and Limited Partners in accordance with their respective partnership percentages, after giving effect to priority income allocations for incentive distributions, if any, to ETP GP, the holder of the IDRs pursuant to our Partnership Agreement, which are declared and paid following the close of each quarter. Earnings in excess of distributions are allocated to ETP GP and Limited Partners based on their respective ownership interests.


13


A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit is as follows:
 
Three Months Ended March 31,
 
2012
 
2011
Net income attributable to partners
$
1,114,733

 
$
247,202

General Partner’s interest in net income
116,537

 
107,539

Limited Partners’ interest in net income
998,196

 
139,663

Additional (losses) earnings allocated from General Partner
(147
)
 
348

Distributions on employee unit awards, net of allocation to General Partner
(9,754
)
 
(1,776
)
Net income available to Limited Partners
$
988,295

 
$
138,235

Weighted average Limited Partner units — basic
226,549,263

 
193,821,128

Basic net income per Limited Partner unit
$
4.36

 
$
0.71

Weighted average Limited Partner units
226,549,263

 
193,821,128

Dilutive effect of unvested Unit Awards
857,221

 
705,472

Weighted average Limited Partner units, assuming dilutive effect of unvested Unit Awards
227,406,484

 
194,526,600

Diluted net income per Limited Partner unit
$
4.35

 
$
0.71



9.
DEBT OBLIGATIONS:
Our debt obligations consist of the following:
 
March 31, 2012
 
December 31, 2011
ETP Senior Notes
$
7,800,000

 
$
6,550,000

Transwestern Senior Notes
870,000

 
870,000

HOLP Senior Notes

 
71,314

ETP Revolving Credit Facility
190,000

 
314,438

Other long-term debt
616

 
10,345

Unamortized discounts
(21,140
)
 
(15,457
)
Fair value adjustments related to interest rate swaps
10,244

 
11,647

Total debt
8,849,720

 
7,812,287

Less: current maturities
(108,224
)
 
(424,117
)
Long-term debt, less current maturities
$
8,741,496

 
$
7,388,170

The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $10.9 million in unamortized discounts and fair value adjustments related to interest rate swaps:
2012 (remainder)
$
108,224

2013
350,105

2014
380,055

2015
750,112

2016
315,116

Thereafter
6,957,004

Total
$
8,860,616


14


Senior Notes
In January 2012, we completed a public offering of $1 billion aggregate principal amount of 5.20% Senior Notes due February 1, 2022 and $1 billion aggregate principal amount of 6.50% Senior Notes due February 1, 2042 and used the net proceeds of $1.98 billion from the offering to fund the cash portion of the purchase price of the Citrus Merger and for general partnership purposes. We may redeem some or all of the notes at any time and from time to time pursuant to the terms of the indenture subject to the payment of a “make-whole” premium. Interest will be paid semi-annually.
In January 2012, we announced a tender offer for approximately $750 million aggregate principal amount of specified series of the ETP Senior Notes. The tender offer consisted of two separate offers: an Any and All Offer and a Maximum Tender Offer. The senior notes described below were repurchased under the Any and All Offer and Maximum Tender Offer for a total cost of $885.9 million and a loss on extinguishment of debt of $115.0 million was recorded during the three months ended March 31, 2012.
In the Any and All Offer, we offered to purchase any and all of our 5.65% Senior Notes due August 1, 2012, at a fixed price. Pursuant to the Any and All Offer, we purchased $292.0 million aggregate principal amount of our 5.65% Senior Notes due August 1, 2012 on January 19, 2012.
In the Maximum Tender Offer, we offered to purchase certain series of outstanding ETP Senior Notes at a fixed spread over the index rate. Pursuant to the Maximum Tender Offer, on February 7, 2012, we purchased $200.0 million aggregate principal amount of our 9.7% Senior Notes due March 15, 2019, $200.0 million aggregate principal amount of our 9.0% Senior Notes due April 15, 2019, and $58.1 million aggregate principal amount of our 8.5% Senior Notes due April 15, 2014.
Revolving Credit Facility
The indebtedness under ETP’s revolving credit facility (the “ETP Credit Facility”) is unsecured and not guaranteed by any of the Partnership’s subsidiaries and has equal rights to holders of our current and future unsecured debt. The indebtedness under the ETP Credit Facility has the same priority of payment as our other current and future unsecured debt.
As of March 31, 2012, we had $190.0 million outstanding under the ETP Credit Facility, and the amount available for future borrowings was $2.28 billion after taking into account letters of credit of $28.3 million. The weighted average interest rate on the total amount outstanding as of March 31, 2012 was 1.74%.
Covenants Related to Our Credit Agreements
We were in compliance with all requirements, tests, limitations, and covenants related to our credit agreements at March 31, 2012.

10.
EQUITY:
Common Units Issued
The change in Common Units during the three months ended March 31, 2012 was as follows:
 
Number of
Units
Outstanding at December 31, 2011
225,468,108

Common Units issued in connection with the Equity Distribution Agreement
1,600,483

Common Units issued in connection with the Distribution Reinvestment Plan
238,314

Common Units issued in connection with the Citrus Merger
2,249,092

Common Units issued under equity incentive plans
7,124

Outstanding at March 31, 2012
229,563,121

During the three months ended March 31, 2012, we received proceeds from units issued pursuant to an Equity Distribution Agreement with Credit Suisse of $76.7 million, net of commissions, which proceeds were used for general partnership purposes. As of March 31, 2012, no Common Units remain available to be issued under this agreement.
In addition to the Equity Distribution Agreement, we have a Distribution Reinvestment Plan (the “DRIP”) which provides Unitholders of record and beneficial owners of our Common Units a voluntary means by which they can increase the number of ETP Common Units they own by reinvesting the quarterly cash distributions they would otherwise receive in the purchase of additional Common Units. The registration statement we filed in connection with the DRIP covers the issuance of up to 5,750,000 Common Units under the DRIP. For the three months ended March 31, 2012, distributions of approximately $10.6

15


million were reinvested under the DRIP resulting in the issuance of 238,314 Common Units. As of March 31, 2012, a total of 5,158,007 Common Units remain available to be issued under this agreement.
Quarterly Distributions of Available Cash
Following are distributions declared and/or paid by us subsequent to December 31, 2011:
Quarter Ended
  
Record Date
  
Payment Date
  
Rate
December 31, 2011
 
February 7, 2012
 
February 14, 2012
 
$0.89375
March 31, 2012
 
May 4, 2012
 
May 15, 2012
 
0.89375
In conjunction with the Citrus Merger, ETE agreed to relinquish its rights to approximately $220 million of the IDR's from ETP that ETE would otherwise be entitled to receive over 16 consecutive quarters.

AOCI
The following table presents the components of AOCI, net of tax:
 
March 31,
2012
 
December 31, 2011
Net gains on commodity related hedges
$
23,361

 
$
6,455

Unrealized gains on available-for-sale securities

 
114

Total AOCI, net of tax
$
23,361

 
$
6,569


11.
UNIT-BASED COMPENSATION PLANS:
During the three months ended March 31, 2012, employees were granted a total of 14,917 unvested awards with five-year service vesting requirements, and directors were granted a total of 2,120 unvested awards with three-year service vesting requirements. The weighted average grant-date fair value of these awards was $46.30 per unit. As of March 31, 2012 a total of 2,377,124 unit awards remain unvested, including the new awards granted during the period. We expect to recognize a total of $70.1 million in compensation expense over a weighted average period of 1.8 years related to unvested awards.

12.
INCOME TAXES:
The components of the federal and state income tax expense of our taxable subsidiaries are summarized as follows:
 
Three Months Ended March 31,
 
2012
 
2011
Current expense (benefit):
 
 
 
Federal
$
(193
)
 
$
5,028

State
3,672

 
3,934

Total
3,479

 
8,962

Deferred expense:
 
 
 
Federal
3,103

 
1,019

State
7,541

 
616

Total
10,644

 
1,635

Total income tax expense
$
14,123

 
$
10,597

The effective tax rate differs from the statutory rate due primarily to Partnership earnings that are not subject to federal and state income taxes at the Partnership level.



16


13.
REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:
Contingent Matters Potentially Impacting the Partnership from Our Investment in Citrus
Florida Gas Phase VIII Expansion.  Florida Gas' Phase VIII Expansion project was placed in-service on April 1, 2011, at an approximate cost of $2.5 billion, including capitalized equity and debt costs. To date, Florida Gas has entered into long-term firm transportation service agreements with shippers for 25-year terms accounting for approximately 74% of the available expansion capacity.
In 2011, CrossCountry Citrus, LLC (CrossCountry Citrus) and Citrus' other stockholder each made sponsor contributions of $37 million in the form of loans to Citrus, net of repayments.   The contributions are related to the costs of Florida Gas' Phase VIII Expansion project.  In conjunction with anticipated sponsor contributions, Citrus has entered into a promissory note in favor of each stockholder for up to $150 million. The promissory notes have a final maturity date of March 31, 2014, with no principal payments required prior to the maturity date, and bear an interest rate equal to a one-month Eurodollar rate plus a credit spread of 1.5%. Amounts may be redrawn periodically under the notes to temporarily fund capital expenditures, debt retirements, or other working capital needs. 
Florida Gas Pipeline Relocation Costs. The FDOT/FTE has various turnpike/State Road 91 widening projects that have impacted or may, over time, impact one or more of Florida Gas' mainline pipelines located in FDOT/FTE rights-of-way. Several FDOT/FTE projects are the subject of litigation in Broward County, Florida. On January 27, 2011, a jury awarded Florida Gas $82.7 million and rejected all damage claims by the FDOT/FTE. On May 2, 2011, the judge issued an order entitling Florida Gas to an easement of 15 feet on either side of its pipelines and 75 feet of temporary work space. The judge further ruled that Florida Gas is entitled to approximately $8 million in interest. In addition to ruling on other aspects of the easement, he ruled that pavement could not be placed directly over Florida Gas' pipeline without the consent of Florida Gas although Florida Gas would be required to relocate the pipeline if it did not provide such consent. He also denied all other pending post-trial motions. The FDOT/FTE filed a notice of appeal on July 12, 2011. Briefing to the Florida Fourth District Court of Appeals (4th DCA) is complete. The 4th DCA granted a request by the FDOT to expedite the appeal. Oral argument was held March 7, 2012. Amounts ultimately received would primarily reduce Florida Gas' property, plant and equipment costs.
Contingent Residual Support Agreement - AmeriGas
In order to finance the cash portion of the purchase price of the Propane Transaction described in Note 5, AmeriGas Finance LLC ("Finance Company"), a wholly owned subsidiary of AmeriGas, issued $550 million in aggregate principal amount of 6.75% Senior Notes due 2020 and $1.0 billion in aggregate principal amount of 7.00% Senior Notes due 2022. AmeriGas borrowed $1.5 billion of the proceeds of the Senior Notes issuance from Finance Company through an intercompany borrowing having maturity dates and repayment terms that mirror those of the Senior Notes (the "Supported Debt").
In connection with the closing of the Propane Transaction, ETP entered into a Contingent Residual Support Agreement ("CRSA") with AmeriGas, Finance Company, AmeriGas Finance Corp. and UGI Corp., pursuant to which ETP will provide contingent, residual support of the Supported Debt as defined in the CRSA.
Interstate Natural Gas Pipeline Regulation
Under the Natural Gas Act, interstate natural gas companies must charge rates that are just and reasonable. In addition, the NGA prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.  On December 21, 2010, FERC certified a contested offer of settlement, which order settled a number of issues related to FGT's rates and terms and conditions of service.  Among other matters, FGT is required to make its next NGA section 4 general rate case filing no later than November 1, 2014. 
Commitments
In the normal course of our business, we purchase, process and sell natural gas pursuant to long-term contracts and we enter into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. We believe that the terms of these agreements are commercially reasonable and will not have a material adverse effect on our financial position or results of operations.
We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2029. Rental expense under these operating leases has been included in operating expenses in the accompanying statements of operations and totaled approximately $5.9 million and $5.0 million for the three months ended March 31, 2012 and 2011, respectively.

17


Our joint venture agreements require that we fund our proportionate share of capital contributions to our unconsolidated affiliates. Such contributions will depend upon our unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.
Litigation and Contingencies
We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and NGLs are flammable and combustible. Serious personal injury and significant property damage can arise in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future.
We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated we accrue the contingent obligation as well as any expected insurance recoverable amounts related to the contingency. As of March 31, 2012 and December 31, 2011, accruals of approximately $0.1 million and $18.2 million, respectively, were reflected on our balance sheets related to these contingent obligations. The decrease in the accrual for the three months ended March 31, 2012 is a result of the contribution of our Propane Business to AmeriGas as discussed in Note 5. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.
The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.
No amounts have been recorded in our March 31, 2012 or December 31, 2011 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.
CrossCountry, the Southern Union subsidiary that indirectly owns a 50% interest in Citrus, filed a petition in the Delaware Court of Chancery seeking a declaratory judgment against El Paso, the owner of the other 50% interest of Citrus, that the Citrus Merger did not breach El Paso's rights under a joint venture agreement related to Citrus. This petition was filed by CrossCountry following an exchange of letters between CrossCountry, El Paso and Southern Union in which El Paso stated that it believed the Citrus Merger violated the provisions of the joint venture agreement. Subsequently, El Paso filed a petition asserting a counterclaim action against CrossCountry, ETP and ETE based on its claim that the Citrus Merger violated El Paso's right of first refusal and, in such petition, El Paso sought a rescission of the Citrus Merger or, alternatively, damages.
On April 18, 2012, the parties to the declaratory judgment action and related counterclaim action entered into a joint stipulation pursuant to which El Paso agreed that the Citrus Merger did not breach the joint venture agreement and that El Paso was not entitled to rescission or damages with respect to the Citrus Merger. On April 20, 2012, the Delaware court granted an order approving the joint stipulation and, as a result, all litigation regarding El Paso's claims with respect to the Citrus Merger has been terminated.
Environmental Matters
Our operations are subject to extensive federal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the business of transporting, storing, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products. As a result, there can be no assurance that significant costs and liabilities will not be incurred. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the issuance of injunctions and the filing of federally authorized citizen suits. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, could result in substantial costs and liabilities. Accordingly, we have adopted policies,

18


practices and procedures in the areas of pollution control, product safety, occupational safety and health, and the handling, storage, use, and disposal of hazardous materials to prevent and minimize material environmental or other damage, and to limit the financial liability, which could result from such events. However, the risk of environmental or other damage is inherent in transporting, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products, as it is with other entities engaged in similar businesses.
We are unable to estimate any losses or range of losses that could result from such developments. Furthermore, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.
Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.
As of March 31, 2012 and December 31, 2011, accruals on an undiscounted basis of $11.4 million and $13.7 million, respectively, were recorded in our consolidated balance sheets as accrued and other current liabilities and other non-current liabilities related to environmental matters.
Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs.
Transwestern conducts soil and groundwater remediation at a number of its facilities. Some of the cleanup activities include remediation of several compressor sites on the Transwestern system for contamination by PCBs. The costs of this work are not eligible for recovery in rates. The total accrued future estimated cost of remediation activities expected to continue through 2025 is $5.8 million, which is included in the aggregate environmental accruals discussed above. Transwestern received approval from the FERC for the continuation of rate recovery of projected soil and groundwater remediation costs not related to PCBs for the term of its rate case settlement.
Transwestern, as part of ongoing arrangements with customers, continues to incur costs associated with containing and removing potential PCBs. Future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. However, such future costs are not expected to have a material impact on our financial position, results of operations or cash flows.
The EPA Spill Prevention, Control and Countermeasures program regulations were recently modified and impose additional requirements on many of our facilities. We expect to expend resources on tank integrity testing and any associated corrective actions as well as potential upgrades to containment structures to comply with the new rules. Costs associated with tank integrity testing and resulting corrective actions cannot be reasonably estimated at this time, but we believe such costs will not have a material adverse effect on our financial position, results of operations or cash flows.
On August 20, 2010, the EPA published new regulations under the federal CAA to control emissions of hazardous air pollutants from existing stationary reciprocal internal combustion engines. The rule will require us to undertake certain expenditures and activities, likely including purchasing and installing emissions control equipment. In response to an industry group legal challenge to portions of the rule in the U.S. Court of Appeals for the D.C. Circuit and a Petition for Administrative Reconsideration to the EPA, on March 9, 2011, the EPA issued a new proposed rule and direct final rule effective on May 9, 2011 to clarify compliance requirements related to operation and maintenance procedures for continuous parametric monitoring systems. If no further changes to the standard are made as a result of comments to the proposed rule, we would not expect that the cost to comply with the rule’s requirements will have a material adverse effect on our financial condition or results of operations. Compliance with the final rule is required by October 2013.
On June 29, 2011, the EPA finalized a rule under the CAA that revised the new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines. The rule became effective on August 29, 2011. The rule modifications may require us to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment, if equipment is replaced or existing facilities are expanded in the future. At this point, we are not able to predict the cost to comply with the rule’s requirements, because the rule applies only to changes we might make in the future.
On April 17, 2012, the EPA issued the final Oil and Natural Gas Sector New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants. The standards revise the new source performance standards for volatile organic compounds from leaking components at onshore natural gas processing plants and new source performance standards

19


for sulfur dioxide emissions from natural gas processing plants. The EPA also established standards for certain oil and gas operations not covered by the existing standards. In addition to the operations covered by the existing standards, the newly established standards regulate volatile organic compound emissions from gas wells, centrifugal compressors, reciprocating compressors, pneumatic controllers and storage vessels. In general, the revised New Source Performance Standards will apply only to sources that are newly constructed or substantially modified or reconstructed in the future, while the revised National Emission Standards for Hazardous Air Pollutants will not require most sources to which they apply to be in compliance until 2015. ETP is reviewing the new standards to determine the impact on its operations.
Our pipeline operations are subject to regulation by the DOT under the PHMSA, pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. For the three months ended March 31, 2012 and 2011, $2.1 million and $1.7 million, respectively, of capital costs and $1.5 million and $2.1 million of operating and maintenance costs have been incurred for pipeline integrity testing. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures.
Our operations are also subject to the requirements of the OSHA and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.

14.
PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:
Commodity Price Risk
We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in the consolidated balance sheets.
We inject and hold natural gas in our Bammel storage facility to take advantage of contango markets (i.e., when the price of natural gas is higher in the future than the current spot price). We use financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities. At the inception of the hedge, we lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract to lock in the sale price. If we designate the related financial contract as a fair value hedge for accounting purposes, we value the hedged natural gas inventory at current spot market prices along with the financial derivative we use to hedge it. Changes in the spread between the forward natural gas prices designated as fair value hedges and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized. Unrealized margins represent the unrealized gains or losses from our derivative instruments using mark-to-market accounting, with changes in the fair value of our derivatives being recorded directly in earnings. These margins fluctuate based upon changes in the spreads between the physical spot price and forward natural gas prices. If the spread narrows between the physical and financial prices, we will record unrealized gains or lower unrealized losses. If the spread widens, we will record unrealized losses or lower unrealized gains. Typically, as we enter the winter months, the spread converges so that we recognize in earnings the original locked-in spread through either mark-to-market adjustments or the physical withdrawal of natural gas.
We are also exposed to market risk on natural gas we retain for fees in our intrastate transportation and storage segment and operational gas sales on our interstate transportation segment. We use financial derivatives to hedge the sales price of this gas, including futures, swaps and options. Certain contracts that qualify for hedge accounting are designated as cash flow hedges of the forecasted sale of natural gas. The change in value, to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statement of operations.

20


Our trading activities include the use of financial commodity derivatives to take advantage of market opportunities. These trading activities are a complement to our transportation and storage segment's operations and are netted in cost of products sold in our consolidated statements of operations. Additionally, we also have trading activities related to power in our “All Other” segment which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy.
Derivatives are utilized in our midstream segment in order to mitigate price volatility and manage fixed price exposure incurred from contractual obligations. We attempt to maintain balanced positions in our marketing activities to protect against volatility in the energy commodities markets; however, net unbalanced positions can exist. Long-term physical contracts are tied to index prices. System gas, which is also tied to index prices, is expected to provide most of the gas required by our long-term physical contracts. When third-party gas is required to supply long-term contracts, a hedge is put in place to protect the margin on the contract. To the extent that financial contracts are not tied to physical delivery volumes, we may engage in offsetting financial contracts to balance our positions. To the extent open commodity positions exist, fluctuating commodity prices can impact our financial position and results of operations, either favorably or unfavorably.
We use propane futures contracts to secure the purchase price of our propane inventory for a percentage of the anticipated sales by our cylinder exchange business. Prior to the deconsolidation of the Propane Business, we also used propane futures contracts to fix the purchase price related to certain fixed price sales contracts.


21


The following table details our outstanding commodity-related derivatives:
 
March 31, 2012
 
December 31, 2011
 
Notional
Volume
 
Maturity
 
Notional
Volume
 
Maturity
Mark-to-Market Derivatives
 
 
 
 
 
 
 
(Trading)
 
 
 
 
 
 
 
Natural Gas (MMBtu):
 
 
 
 
 
 
 
Basis Swaps IFERC/NYMEX (1)
11,280,000

 
2012-2013
 
(151,260,000
)
 
2012-2013
Power (Thousand Megawatt):
 
 
 
 
 
 
 
Forwards
(1,000
)
 
2012-2013
 

 
Options — Puts
32

 
2012
 

 
Options — Calls
84

 
2012
 

 
(Non-Trading)
 
 
 
 
 
 
 
Natural Gas (MMBtu):
 
 
 
 
 
 
 
Basis Swaps IFERC/NYMEX
(43,882,500
)
 
2012-2013
 
(61,420,000
)
 
2012-2013
Swing Swaps IFERC
(62,117,500
)
 
2012-2013
 
92,370,000

 
2012-2013
Fixed Swaps/Futures
(2,042,500
)
 
2012-2013
 
797,500

 
2012
Forward Physical Contracts
(43,604,214
)
 
2012
 
(10,672,028
)
 
2012
Propane (Gallons):
 
 
 
 
 
 
 
Forwards/Swaps
6,571,500

 
2012-2013
 
38,766,000

 
2012-2013
Fair Value Hedging Derivatives
 
 
 
 
 
 
 
(Non-Trading)
 
 
 
 
 
 
 
Natural Gas (MMBtu):
 
 
 
 
 
 
 
Basis Swaps IFERC/NYMEX
(25,920,000
)
 
2012-2013
 
(28,752,500
)
 
2012
Fixed Swaps/Futures
(55,690,000
)
 
2012-2013
 
(45,822,500
)
 
2012
Hedged Item — Inventory
55,690,000

 
2012
 
45,822,500

 
2012
Cash Flow Hedging Derivatives
 
 
 
 
 
 
 
(Non-Trading)
 
 
 
 
 
 
 
Natural Gas (MMBtu):
 
 
 
 
 
 
 
Basis Swaps IFERC/NYMEX
(17,400,000
)
 
2012-2013
 

 
Fixed Swaps/Futures
(35,650,000
)
 
2012-2013
 

 
Options — Puts
2,700,000

 
2012
 
3,600,000

 
2012
Options — Calls
(2,700,000
)
 
2012
 
(3,600,000
)
 
2012
(1)
Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.
We expect gains of $19.9 million related to commodity derivatives to be reclassified into earnings over the next 12 months related to amounts currently reported in AOCI. The amount ultimately realized, however, will differ as commodity prices change and the underlying physical transaction occurs.
Interest Rate Risk
We are exposed to market risk for changes in interest rates. In order to maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We manage our current interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of our anticipated debt issuances.

22


We had the following interest rate swaps outstanding as of March 31, 2012 and December 31, 2011, none of which were designated as hedges for accounting purposes:
Term
 
Type (1)
 
Notional Amount Outstanding
March 31, 2012
 
December 31, 2011
May 2012(2)
 
Forward starting to pay a fixed rate of 2.59% and receive a floating rate
 
$

 
$
350,000

August 2012(2)
 
Forward starting to pay a fixed rate of 3.51% and receive a floating rate
 

 
500,000

July 2013(2)
 
Forward starting to pay a fixed rate of 4.02% and receive a floating rate
 
400,000

 
300,000

July 2014(2)
 
Forward starting to pay a fixed rate of 4.26% and receive a floating rate
 
400,000

 

July 2018
 
Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70%
 
600,000

 
500,000

 
(1) 
Floating rates are based on 3-month LIBOR.
(2) 
Represents the effective date. These forward starting swaps have a term of 10 years with a mandatory termination date the same as the effective date.
Credit Risk
We maintain credit policies with regard to our counterparties that we believe minimize our overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings), collateral requirements under certain circumstances and the use of standardized agreements, which allow for netting of positive and negative exposure associated with a single or multiple counterparties.
Our counterparties consist primarily of petrochemical companies and other industrials, small to major oil and gas producers and power generation companies. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. Currently, management does not anticipate a material adverse effect on our financial position or results of operations as a result of counterparty nonperformance.
We utilize master-netting agreements and have maintenance margin deposits with certain counterparties in the OTC market and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets. The Partnership had net deposits with counterparties of $62.0 million and $66.2 million as of March 31, 2012 and December 31, 2011, respectively.
For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheet and recognized in net income or other comprehensive income.

23


Derivative Summary
The following table provides a balance sheet overview of the Partnership’s derivative assets and liabilities as of March 31, 2012 and December 31, 2011:
 
Fair Value of Derivative Instruments
 
Asset Derivatives
 
Liability Derivatives
 
March 31, 2012
 
December 31, 2011
 
March 31, 2012
 
December 31, 2011
Derivatives designated as hedging instruments:
 
 
 
 
 
 
 
Commodity derivatives (margin deposits)
$
58,103

 
$
77,197

 
$
(486
)
 
$
(819
)
 
58,103

 
77,197

 
(486
)
 
(819
)
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Commodity derivatives (margin deposits)
187,403

 
227,337

 
(211,638
)
 
(251,268
)
Commodity derivatives
14,565

 
708

 
(12,565
)
 
(4,844
)
Interest rate derivatives
33,998

 
36,301

 
(88,092
)
 
(117,020
)
 
235,966

 
264,346

 
(312,295
)
 
(373,132
)
Total derivatives
$
294,069

 
$
341,543

 
$
(312,781
)
 
$
(373,951
)
The commodity derivatives (margin deposits) are recorded in “Other current assets” on our consolidated balance sheets. The remainder of the derivatives are recorded in “Price risk management assets/liabilities.”
We disclose the non-exchange traded financial derivative instruments as price risk management assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date.

The following tables summarize the amounts recognized with respect to our derivative financial instruments for the periods presented:
 
Change in Value Recognized in OCI on Derivatives
(Effective Portion)
 
Three Months Ended March 31,
 
2012
 
2011
Derivatives in cash flow hedging relationships:
 
 
 
Commodity derivatives
$
20,429

 
$
6,104

Total
$
20,429

 
$
6,104

 
 
Location of Gain/(Loss)
Reclassified from
AOCI into Income
(Effective Portion)
 
Amount of Gain/(Loss)
Reclassified from AOCI into Income
(Effective Portion)
 
 
 
Three Months Ended March 31,
 
 
 
2012
 
2011
Derivatives in cash flow hedging relationships:
 
 
 
 
Commodity derivatives
Cost of products sold
 
$
3,435

 
$
16,968

Total
 
 
$
3,435

 
$
16,968

 

24


 
Location of Gain/(Loss)
Reclassified from
AOCI into Income
(Ineffective Portion)
 
Amount of Gain/(Loss) Recognized
in Income on Ineffective Portion
 
 
 
Three Months Ended March 31,
 
 
 
2012
 
2011
Derivatives in cash flow hedging relationships:
 
 
 
 
Commodity derivatives
Cost of products sold
 
$
47

 
$
5

Total
 
 
$
47

 
$
5

 
 
Location of Gain/(Loss)
Recognized in Income
on Derivatives
 
Amount of Gain/(Loss) Recognized in
Income representing hedge ineffectiveness
and amount excluded from the assessment of
effectiveness
 
 
 
Three Months Ended March 31,
 
 
 
2012
 
2011
Derivatives in fair value hedging relationships (including hedged item):
 
 
 
 
Commodity derivatives
Cost of products sold
 
$
(9,173
)
 
$
6,417

Total
 
 
$
(9,173
)
 
$
6,417


 
Location of Gain/(Loss)
Recognized in Income
on Derivatives
 
Amount of Gain/(Loss)
Recognized in Income
on Derivatives
 
 
 
Three Months Ended March 31,
 
 
 
2012
 
2011
Derivatives not designated as hedging instruments:
 
 
 
 
 
Commodity derivatives - Trading
Cost of products sold
 
$
(10,586
)
 
$

Commodity derivatives - Non-trading
Cost of products sold
 
(2,944
)
 
6,379

Interest rate derivatives
Gains on non-hedged
interest rate derivatives
 
27,895

 
1,779

Total
 
 
$
14,365

 
$
8,158


We recognized $17.9 million of unrealized losses on commodity derivatives not in fair value hedging relationships (including the ineffective portion of commodity derivatives in cash flow hedging relationships) for the three months ended March 31, 2011. For the three months ended March 31, 2012 and 2011 we recognized unrealized losses of $86.2 million and $8.9 million, respectively, on commodity derivatives and related hedged inventory accounted for as fair value hedges.

15.
RELATED PARTY TRANSACTIONS:
We provide Regency with certain natural gas and NGLs sales and transportation services and compression equipment, and Regency provides us with certain contract compression services. For the three months ended March 31, 2012, we recorded revenues of $8.1 million, cost of products sold of $6.1 million and operating expenses of $0.1 million related to transactions with Regency. For the three months ended March 31, 2011, we recorded revenues of $11.5 million, cost of products sold of $11.0 million and operating expenses of $1.5 million related to transactions with Regency.
We received $4.4 million and $4.9 million in management fees from ETE for the provision of various general and administrative services for ETE’s benefit for the three months ended March 31, 2012 and 2011, respectively. These management fees include the provision of various general and administrative services for Regency. For the three months ended March 31, 2012 and 2011, we recorded from Regency $1.8 million and $2.3 million, respectively, for reimbursement of various general and administrative expenses incurred by us.



25


16.
OTHER INFORMATION:
The tables below present additional detail for certain balance sheet captions.
Other Current Assets
Other current assets consisted of the following:
 
March 31,
2012
 
December 31, 2011
Deposits paid to vendors
$
62,043

 
$
66,231

Prepaid expenses and other
83,029

 
113,909

Total other current assets
$
145,072

 
$
180,140

Other Non-Current Assets, net
Other non-current assets, net consisted of the following:
 
March 31,
2012
 
December 31, 2011
Unamortized financing costs (3 to 30 years)
$
61,866

 
$
46,618

Regulatory assets
88,214

 
88,993

Other
16,183

 
23,990

Total other non-current assets, net
$
166,263

 
$
159,601


Accrued and Other Current Liabilities
Accrued and other current liabilities consisted of the following:
 
March 31,
2012
 
December 31, 2011
Interest payable
$
149,004

 
$
142,616

Customer advances and deposits
5,006

 
84,300

Accrued capital expenditures
199,937

 
196,789

Accrued wages and benefits
25,156

 
67,266

Taxes payable other than income taxes
53,082

 
77,073

Income taxes payable
17,068

 
14,422

Other
55,360

 
46,736

Total accrued and other current liabilities
$
504,613

 
$
629,202


17.
REPORTABLE SEGMENTS:
Our financial statements reflect five reportable segments, which conduct their business exclusively in the United States of America, as follows:
intrastate natural gas transportation and storage;
interstate natural gas transportation;
midstream;
NGL transportation and services; and
retail propane and other retail propane related operations.
Intersegment and intrasegment transactions are generally based on transactions made at market-related rates. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.

26


Revenues from our intrastate transportation and storage segment are primarily reflected in natural gas sales and gathering, transportation and other fees. Revenues from our interstate transportation segment are primarily reflected in gathering, transportation and other fees. Revenues from our midstream segment are primarily reflected in natural gas sales, NGL sales and gathering, transportation and other fees. Revenues from our NGL transportation and services segment are primarily reflected in NGL sales and gathering, transportation and other fees. Revenues from our retail propane and other retail propane related segment are primarily reflected in retail propane sales and other.
We previously reported segment operating income as a measure of segment performance. We have revised certain reports provided to our chief operating decision maker to assess the performance of our business to reflect Segment Adjusted EBITDA. We define Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities includes unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Segment Adjusted EBITDA reflects amounts for less than wholly owned subsidiaries and unconsolidated affiliates based on the Partnership's proportionate ownership. Based on the change in our segment performance measure, we have recast the presentation of our segment results for the prior year to be consistent with the current year presentation.
The following tables present the financial information by segment for the following periods:
 
Three Months Ended March 31,
 
2012
 
2011
Revenues:
 
 
 
Intrastate natural gas transportation and storage:
 
 
 
Revenues from external customers
$
446,796

 
$
588,678

Intersegment revenues
35,257

 
183,081

 
482,053

 
771,759

Interstate natural gas transportation — revenues from external customers
128,276

 
105,101

Midstream:
 
 
 
Revenues from external customers
454,099

 
413,195

Intersegment revenues
100,459

 
238,061

 
554,558

 
651,256

NGL transportation and services:
 
 
 
Revenues from external customers
154,268

 

Intersegment revenues
13,283

 

 
167,551

 

Retail propane and other retail propane related — revenues from external customers
80,006

 
557,215

All other:
 
 
 
Revenues from external customers
42,415

 
23,388

Intersegment revenues
8,157

 
14,427

 
50,572

 
37,815

Eliminations
(157,156
)
 
(435,569
)
Total revenues
$
1,305,860

 
$
1,687,577



27


 
Three Months Ended March 31,
 
2012
 
2011
Segment Adjusted EBITDA
 
 
 
Intrastate transportation and storage
$
192,269

 
$
172,815